Recent developments in drillstring software modeling enable prediction of several key drillstring characteristics to reduce cost and risk. One such development is Cerberus for Drilling (CfD), jointly developed by NOV CTES and Fernley Procter.

Dynamic finite element analysis
Many commercial torque and drag (T&D) models are “soft-string,” static models that ignore the effects of drillstring bending stiffness on wall-contact forces and incorrectly predict friction force. They are unable to calculate dynamic transients due to torsion loading or jarring. Soft-string models are appropriate for selected T&D calculations, but they are unable to perform some of the more sophisticated calculations required to identify potential failure modes that may be encountered in more challenging well bores. CfD uses a 3-D finite element analysis engine that can perform either static or dynamic calculations. This engine provides a dynamic “stiff-string” model for conventional T&D type calculations and can also be used for the more complicated calculations presented here.

Identifying the limits
The primary focus of CfD is drillstring design. It incorporates the NS-14 design limits and the Von Mises combined stress limits. There are two sets of limits, one for the tool joint and one for the pipe body or tube (Figure 1). The tube limits consider the loads and torques required to yield the pin or box along with the applied torque at which the shoulder separates. The maximum tension limit is determined by these limits for a calculated (or user-specified) makeup torque. Tube limits include conventional yield, allowable and working loads (slip crush limits) as well as the combined Von Mises limits, which include the effects of torque, bending and pressures inside and outside the tube. These limits (along with buckling loads) are calculated and plotted against drillstring depth in the T&D analysis, enabling the user to determine if the drillstring is approaching any of the limits.

The application allows easy comparison of multiple field and drillstring design scenarios. A drillstring may be run in two different well sections (in the same well or in different wells) to compare results for each well section. Two drillstring designs may be compared by running them in the same well section. This unique approach reduces drillstring design time and allows quick optimization of various drillstring sections. There are special sections for handling the design of strings used in expandable tubular applications.

Drillstring fatigue failure avoidance
The most common failure mechanism for drillstring components is fatigue, with more than 40% of all failures. Of all drillpipe tube failures, more than 50% are due to fatigue. Advanced drilling software fatigue modeling promises to greatly reduce these types of failures.

Rotating a joint of drill pipe bent around a dogleg causes fatigue damage in the wall of the pipe, which accumulates until a crack initiates. Other effects such as torque, corrosion and material properties can increase this fatigue damage. Continued rotation causes the crack to propagate through the wall thickness. When the crack penetrates the entire wall thickness, a washout occurs. Thus, two main components require analysis:
• Fatigue analysis requires a complex, multi-axial alternating stress state calculation to determine the amount of damage per rotation versus varying amounts of torque, axial force, pressure differential and bending.
• Crack propagation analysis uses a similar multi-axial alternating stress calculation but then uses fracture mechanics to determine the amount of crack growth per revolution.

Historically, drillstring fatigue calculation has only focused on the second component. Drill strings are typically inspected for cracks. If no cracks are found, it is assumed there is a crack smaller than the resolution of the inspection equipment. The fatigue is tracked until the fracture mechanics calculation determines that a washout might occur. Then the drill string is inspected again. If no cracks are found, the fatigue calculation is reset to the initial crack size. This allows continuous use of the drill string, with repeated inspections.

This process is sufficient to avoid drillstring washouts. However, it does not enable calculation of the entire life of the drill string and thus is difficult to compare field and test data because no one knows when a crack actually initiates. This process often results in a shorter inspection interval than is actually required, which is extremely costly. CfD calculates both components of this problem to determine the complete life of the drill string.

Tracking drillstring fatigue for each joint of pipe as it is run through many different well sections is a challenging problem. A database is maintained for each section of the drill string with separate records for each joint. A section is composed of pipe that has all the same properties (diameters, connections, materials, etc.). It is possible to move joints around or replace joints within a section, thus prolonging the life of the entire string before re-inspection.

Bit stick and stick slip
Torsional overload of the smaller string connections is a significant problem for drilling with mixed drillstring sizes especially in stick-slip conditions or when a string stalls. But damage to drillstring connections often does not become apparent until the drill string is inspected.

Dynamic calculations available in CfD allow simulations including axial dynamic situations such as jarring and rig heave analysis, torsional dynamic situations such as the drill string becoming stuck (bit stick) and stick slip. The modeling enables users to understand when there is a large risk of failure if one of these situations occurs.

When a bit (or any point along the drill string) suddenly becomes stuck, a torsional wave travels from the bit up the drill string to the surface. These torsional waves travel at the torsional speed of sound, which is approximately 10,500 ft/sec (3,200 m/sec) in a steel drill string. When this wave arrives at surface, the surface torque increases, and a reflected wave travels back down the drill string. Assuming the top drive continues to rotate, the surface torque increases in steps (due to the traveling of torsional waves up and down the drill string) until the torque limit of the top drive is reached.

The same type of calculation can be used to simulate slip stick. As in the bit stick case, this calculation assumes that the drill string is rotating at a constant speed, when the bit suddenly sticks. The torque at the bit increases to some specified amount, at which time the bit slips and again begins to rotate. When the bit speed drops below a specified speed, it sticks again.

Figure 2 illustrates an example in which the drill string was initially turning at 100 RPM when the bit stuck. The torque at bit increased to 5,000 ft (1,525 m) lbf and the bit subsequently released. When the bit speed dropped below 50 rpm, the bit stuck again. Though the torque fluctuation at the bit makes it obvious that slip stick is occurring, the torque fluctuation at surface is less obvious. The bit speed varies between 0 (when the bit is stuck) and 300 rpm.
A significant number of extremely costly failures can be attributed to this mechanism. The modeling software can help to prevent them.